This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present techniques. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present techniques. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
The production of hydrocarbons from a reservoir oftentimes carries with it the incidental production of non-hydrocarbon gases. Such gases include contaminants such as hydrogen sulfide (H2S), carbon dioxide (CO2), and water. When H2S or CO2 are produced as part of a hydrocarbon gas stream, such as methane or ethane, the raw gas stream is sometimes referred to as “sour gas.” The H2S and CO2 are often referred to together as “acid gases.”
In addition to hydrocarbon production streams, acid gases may be associated with synthesis gas streams, or with refinery gas streams. Acid gases may also be present within so-called flash gas streams in gas processing facilities. Further, acid gases may be generated by the combustion of coal, natural gas, or other carbonaceous fuels.
Natural gas streams may contain not only H2S or CO2, but may also contain other “acidic” impurities. These include mercaptans and other trace sulfur compounds (SOx). In addition, natural gas streams may contain water. Such impurities are often removed prior to industrial or residential use.
Processes have been devised to remove contaminants from a raw natural gas stream. In the case of acid gases, cryogenic gas processing is sometimes used, particularly to remove CO2 to prevent line freezing and orifice plugging. In other instances, particularly with H2S removal, the hydrocarbon fluid stream is treated with a solvent. Solvents may include chemical solvents such as amines Examples of amines used in sour gas treatment include monoethanol amine (MEA), diethanol amine (DEA), and methyl diethanol amine (MDEA).
Physical solvents are sometimes used in lieu of amine solvents. Examples include Selexol® and Rectisol™. In some instances, hybrid solvents, meaning mixtures of physical and chemical solvents, have been used. An example is Sulfinol®. In addition, the use of amine-based acid gas removal solvents is common.
Amine-based solvents rely on a chemical reaction with the acid gases. The reaction process is sometimes referred to as “gas sweetening.” Such chemical reactions are generally more effective than the physical-based solvents, particularly at feed gas pressures below about 300 psia (2.07 MPa). There are instances where special chemical solvents such as Flexsorb™ are used, particularly for selectively removing H2S from CO2-containing gas streams.
As a result of the gas sweetening process, a treated or “sweetened” gas stream is created. The sweetened gas stream is substantially depleted of H2S and/or CO2 components. The sweetened gas stream can be further processed for liquids recovery, that is, by condensing out heavier hydrocarbon gases. The sweetened gas stream may be sold into a pipeline or may be used for liquefied natural gas (LNG) feed if the CO2 concentration is less than, for example, about 50 ppm. In addition, the sweetened gas stream may be used as feedstock for a gas-to-liquids process, and then ultimately used to make waxes, butanes, lubricants, glycols, or other petroleum-based products. The extracted CO2 may be sold, or may be injected into a subterranean reservoir for enhanced oil recovery (EOR) operations.
When a natural gas stream contains water, a dehydration process is usually undertaken before acid gas removal. This is done through the use of glycol or other desiccant in a water separator. The dehydration of natural gas is performed to control the formation of gas hydrates and to prevent corrosion of distribution pipelines. The formation of gas hydrates and the corrosion of distribution pipelines can cause a decrease in flow volume as well as frozen control valves, plugged orifices, and other operating problems.
Traditionally, the removal of acid gases or water from a raw natural gas stream using a chemical solvent (or desiccant) involves counter-currently contacting the raw natural gas stream with the chemical solvent. The raw natural gas stream is introduced into the bottom section of a contacting tower. At the same time, the chemical solvent is directed into a top section of the tower. The tower has trays, packing, or other “internals.” As the chemical solvent cascades through the internals, it absorbs the undesirable components, carrying them away through the bottom of the contacting tower as part of a “rich” solvent solution. At the same time, gaseous fluid that is largely depleted of the undesirable components exits at the top of the tower.
The rich solvent or rich glycol that exits the contactor is sometimes referred to as an absorbent liquid. Following absorption, a process of regeneration (also called “desorption”) may be employed to separate contaminants from the active solvent of the absorbent liquid. This produces a “lean” solvent or a “lean” glycol that is then typically recycled into the contacting tower for further absorption.
Known counter-current contactors used for dehydration or for H2S and CO2 absorption tend to be very large and heavy. This creates particular difficulty in offshore oil and gas production applications, where smaller equipment is desirable. Further, the transport and set-up of large tower-based facilities is difficult for shale gas production operations that frequently take place in remote locations.